Dolostones in the Cambrian Longwangmiao Formation have become one of the most significant gas exploration domains in China. Over a trillion cubic meters of gas reservoirs have been discovered in the Gaoshiti-Moxi area; however, the origins and distribution of the dolostone reservoirs are not well understood. This work discussed the geology and geochemistry of the dolostone reservoirs in the Longwangmiao Formation to determine their origin and distribution. Two understandings are acquired: firstly, a carbonate ramp provided excellent conditions for grain beach deposition, while the presence of a hypersaline lake was favorable for the contemporaneous dolomitization of grain beach deposits. Petrographic and geochemical evidence further confirm that the Longwangmiao dolostone was formed during the contemporaneous stage. Secondly, the reservoir characteristics indicate that the grain beach sediments provide material basis for the development of the Longwangmiao dolostone reservoirs. Reservoir dissolution simulation experiments show that the porosity of the reservoirs was formed by dissolution during contemporaneous and burial stages. The dissolution pores formed during the contemporaneous stage were controlled by sequence interfaces. The large scale dissolution vugs formed during the burial stage subsequently spread along the pre-existing porosity and fracture zones. This study therefore identified that the development of grain dolostone reservoirs in a shallow water ramp under arid climatic conditions generally met the following conditions: (1) reefal beach deposits lay a foundation for reservoir development; (2) superficial conditions are an important determining factor for reservoir porosity; and (3) burial conditions provide environment for porosity preservation and modification.
Widespread replacement dolomite occurs commonly in the geologic record. These dolomites are generally characterized by different crystal sizes and shapes that have at times been interpreted to represent multistage dolomitization; although the variation of dolomite texture could also have resulted from the recrystallization of precursor dolomite. It is important, but challenging, to differentiate these two scenarios to better understand the nature of dolomite and the associated processes of dolomitization. Our study explores this problem by using δ26Mg, δ13C, and δ18O isotopes to characterize the different crystal morphologies exhibited by Ordovician dolomites from the Tarim Basin, China. Although the dolomites show distinct textures and crystal morphologies, there are no discernible trends in their δ26Mg values (from −1.66 to −2.39‰), suggesting that these dolomites were formed by the same dolomitizing fluid. This interpretation is supported by an overlapping range of δ13C values (from 0.46 to −1.89‰). By contrast, the δ18O data demonstrate a wide range of values, from −3.8‰ to −8.8‰, reflecting the different degree of recrystallization with increasing burial temperatures. We suggest that the Mg and C isotopes remained unchanged during recrystallization because Mg and C were rock-buffered, so the recrystallized dolomite inherited Mg and C from the precursor dolomite. Based on these results, it appears that Mg isotopes, together with conventional OC isotopes, can provide a diagenetically robust geochemical tracer for identifying dolomite recrystallization in the geological record.
There are various genetic types of natural gas in eastern China, which are mainly of biogenic gas, abiogenic alkane gas and abiogenic CO 2 . Large biogenic gas fields discovered at present are mainly distributed in Ying-Qiong basin (Ya13- 1, Ledong22–1, Dongfang1–1), Pearl River Mouth basin (Panyu30–1), Eastern China Sea basin (Chunxiao gas field) and Taixi basin (Tiezhanshan gas field) in the continental shelf, and carbon isotope of ethane is heavier than −28‰, which shows that the gas is coal-derived. Large abiogenic alkane gas fields are distributed in the deep part of Songliao basin (Xingcheng gas field, etc), and the natural gas is characterized by heavy isotope (δ 13 C 1 >−30‰), negative carbon isotope series and R/Ra>0.5. CO 2 gas fields distribute widely from Songliao basin in the north to Ying-Qiong basin in the south, and total 35 CO 2 gas fields have been discovered in these areas with CO 2 content more than 60% and d 13 Cco 2 heavier than −28‰.
Northeastern Sichuan Basin is one of the most significant areas for natural gas exploration in China, and Puguang and Maoba are the two most important and typical gas fields there. The common characteristics of the natural gases in the Puguang and Maoba gas fields include extremely high dryness, high H 2 S contents, high δ 13 C 1 values, with a wide range of δ 13 C 2 values. Based on gas composition and stable carbon isotope values, natural gases in the study area are classified into three genetic groups, derived from type III kerogen, type II kerogen and those with a complex origin. The latter group is most likely the result of mixing between low maturity ethane inherited from earlier oil accumulation and high maturity methane generated from subsequent in-reservoir oil cracking and thermochemical sulfate reduction. In conjunction with regional source rock data, the Upper Permian Longtan Formation is considered to be the main source rock for the gases in the Feixianguan-Changxing reservoirs of the Puguang and Maoba gas fields.
A new method for reconstructing the geological history of hydrocarbon accumulation is developed, which are constrained by U-Pb isotope age and clumped isotope (Δ47) temperature of host minerals of hydrocarbon-bearing inclusions. For constraining the time and depth of hydrocarbon accumulation by the laser in-situ U-Pb isotope age and clumped isotope temperature, there are two key steps: (1) Investigating feature, abundance and distribution patterns of liquid and gaseous hydrocarbon inclusions with optical microscopes. (2) Dating laser in-situ U-Pb isotope age and measuring clumped isotope temperature of the host minerals of hydrocarbon inclusions. These technologies have been applied for studying the stages of hydrocarbon accumulation in the Sinian Dengying gas reservoir in the paleo-uplift of the central Sichuan Basin. By dating the U-Pb isotope age and measuring the temperature of clumped isotope (Δ47) of the host minerals of hydrocarbon inclusions in dolomite, three stages of hydrocarbon accumulation were identified: (1) Late Silurian: the first stage of oil accumulation at (416±23) Ma. (2) Late Permian to Early Triassic: the second stage of oil accumulation between (248±27) Ma and (246.3±1.5) Ma. (3) Yanshan to Himalayan period: gas accumulation between (115±69) Ma and (41±10) Ma. The reconstructed hydrocarbon accumulation history of the Dengying gas reservoir in the paleo-uplift of the central Sichuan Basin is highly consistent with the tectonic-burial history, basin thermal history and hydrocarbon generation history, indicating that the new method is a reliable way for reconstructing the hydrocarbon accumulation history.
Mesozoic marine shale oil was found in the Qiangtang Basin by a large number of hydrocarbon geological surveys and shallow drilling sampling. Based on systematic observation and experimental analysis of outcrop and core samples, the deposition and development conditions and characteristics of marine shale are revealed, the geochemical and reservoir characteristics of marine shale are evaluated, and the layers of marine shale oil in the Mesozoic are determined. The following geological understandings are obtained. First, there are two sets of marine organic-rich shales, the Lower Jurassic Quse Formation and the Upper Triassic Bagong Formation, in the Qiangtang Basin. They are mainly composed of laminated shale with massive mudstone. The laminated organic-rich shale of the Quse Formation is located in the lower part of the stratum, with a thickness of 50–75 m, and mainly distributed in southern Qiangtang Basin and the central-west of northern Qiangtang Basin. The laminated organic-rich shale of the Bagong Formation is located in the middle of the stratum, with a thickness of 250–350 m, and distributed in both northern and southern Qiangtang Basin. Second, the two sets of laminated organic-rich shales develop foliation, and various types of micropores and microfractures. The average content of brittle minerals is 70%, implying a high fracturability. The average porosity is 5.89%, indicating good reservoir physical properties to the level of moderate–good shale oil reservoirs. Third, the organic-rich shale of the Quse Formation contains organic matters of types II1 and II2, with the average TOC of 8.34%, the average content of chloroform bitumen 'A' of 0.66%, the average residual hydrocarbon generation potential (S1+S2) of 29.93 mg/g, and the Ro value of 0.9%–1.3%, meeting the standard of high-quality source rock. The organic-rich shale of the Bagong Formation contains mixed organic matters, with the TOC of 0.65%–3.10% and the Ro value of 1.17%–1.59%, meeting the standard of moderate source rock. Fourth, four shallow wells (depth of 50–250 m) with oil shows have been found in the organic shales at 50–90 m in the lower part of the Bagong Formation and 30–75 m in the middle part of the Quse Formation. The crude oil contains a high content of saturated hydrocarbon. Analysis and testing of outcrop and shallow well samples confirm the presence of marine shale oil in the Bagong Formation and the Quse Formation. Good shale oil intervals in the Bagong Formation are observed in layers 18–20 in the lower part of the section, where the shales with (S0+S1) higher than 1 mg/g are 206.7 m thick, with the maximum and average (S0+S1) of 1.92 mg/g and 1.81 mg/g, respectively. Good shale oil intervals in the Quse Formation are found in layers 4–8 in the lower part of the section, where the shales with (S0+S1) higher than 1 mg/g are 58.8 m thick, with the maximum and average (S0+S1) of 6.46 mg/g and 2.23 mg/g, respectively.
Through the development and calibration of a reference material which is 209.8 Ma old using a newly-developed Laser Ablation (LA) Multi-Collector Inductively Coupled Plasma Mass Spectrometry (MC-ICP-MS) technique, we successfully overcome the difficulty in sampling and dating ultra-low U-Pb ancient marine carbonates, which was previously untenable by isotope dilution (ID) methods. We developed the LA-MC-ICP-MS in situ U-Pb dating technique for ancient marine carbonates for the study of diagenesis-porosity evolution history in Sinian Dengying Formation, Sichuan Basin. By systematically dating of dolomitic cements from vugs, matrix pores and fractures, we found that the burial and diagenetic process of dolomite reservoirs in Sinian Dengying Formation was characterized by progressive filling-up of primary pores and epigenic dissolution vugs. The filling of vugs happened in three stages, early Caledonian, late Hercynian-Indosinian and Yanshanian-Himalayan, while the filling of matrix pores mainly took place in early Caledonian. The unfilled residual vugs, pores and fractures constitute the main reservoir sapce. Based on the above knowledge, we established the diagenesis-porosity evolution history of the dolomite reservoir in Sinian Dengying Formation, Sichuan Basin. These findings are highly consistent with the tectonic-burial and basin thermal histories of the study area. Our study confirmed the reliability of this in situ U-Pb dating technique, which provides an effective way for the investigation of diagenesis-porosity evolution history and evaluation of porosity in ancient marine carbonate reservoirs before hydrocarbon migration.
'%3e%3cpath fill='%23012169' d='M0 0v30h60V0z'/%3e%3cpath stroke='%23fff' stroke-width='6' d='m0 0 60 30m0-30L0 30'/%3e%3cpath stroke='%23C8102E' stroke-width='4' d='m0 0 60 30m0-30L0 30' clip-path='url(%23b)'/%3e%3cpath stroke='%23fff' stroke-width='10' d='M30 0v30M0 15h60'/%3e%3cpath stroke='%23C8102E' stroke-width='6' d='M30 0v30M0 15h60'/%3e%3c/g%3e%3c/svg%3e)
'/%3e%3cuse xlink:href='%23a' transform='rotate(23.036 .093 25.536)'/%3e%3cuse xlink:href='%23a' transform='rotate(45.87 1.273 16.18)'/%3e%3cuse xlink:href='%23a' transform='rotate(69.945 .996 12.078)'/%3e%3cuse xlink:href='%23a' transform='rotate(20.66 -19.689 31.932)'/%3e%3c/svg%3e)